Atlas America Series 27-2006 10K 2010 Annual report

United States
Securities and Exchange Commission

Washington, D.C. 20549

Form 10-K

(Mark One)


þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2010


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 0-52615

ATLAS AMERICA SERIES 27-2006 L.P.

(Exact name of registrant as specified in its charter)


Delaware		20-5242075
(State or other jurisdiction of		(I.R.S. Employer
Incorporation or organization)		Identification No.)


Westpointe Corporate Center One
1550 Coraopolis Heights Road, 2nd Floor
Moon Township, PA		15108
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number(412) 262-2830

Securities registered under Section 12(b) of the Exchange Act.


Title of each class		Name of each exchange on which registered
None		None

Securities registered under Section 12(g) of the Exchange Act: Investor General Partner Units and Limited Partner Units

(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yeso Noþ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yeso Noþ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-Kþ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer”, “non-accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one):


Large accelerated filero		Accelerated filero		Non-accelerated filero		Smaller reporting companyþ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yeso Noþ

DOCUMENTS INCORPORATED BY REFERENCE: None

ATLAS AMERICA SERIES 27-2006 L.P.
(A DELAWARE LIMITED PARTNERSHIP)
INDEX TO ANNUAL REPORT
ON FORM 10-K


	PAGE
PART I

Item 1: Business		3-5

Item 2: Properties		5-9

Item 3: Legal Proceedings		10

Item 4: (Removed and Reserved)		10

PART II

Item 5: Market for Registrant’s Common Equity and Related Security Holder Matters		10-11

Item 7: Management’s Discussion and Analysis of Financial Condition or Plan of Operations		11-15

Item 8: Financial Statements		16-35

Item 9: Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		35

Item 9A: Controls and Procedures		35-36

Item 9B: Other Information		36

PART III

Item 10: Directors and Executive Officers of the Registrant		36-38

Item 11: Executive Compensation		38

Item 12: Security Ownership of Certain Beneficial Owners and Management		38

Item 13: Certain Relationships and Related Party Transactions		38-39

Item 14: Principal Accountant Fees and Services		39

PART IV

Item 15: Exhibits		40

SIGNATURES		41

EX-23.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2
Exhibit 99.1

The matters discussed within this report include forward-looking statements. These statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “should,” or “will,” or the negative thereof or other variations thereon or comparable terminology. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements. We have based these forward-looking statements on our current expectations, assumptions, estimates and projections. While we believe these expectations, assumptions, estimates and projections are reasonable, such forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control. These and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements.

PART I


ITEM 1.		BUSINESS

General.We are a Delaware limited partnership, formed on July 21, 2006 with Atlas Resources, LLC serving as our Managing General Partner (Atlas Resources or “MGP”). Atlas Resources, LLC is an indirect subsidiary of Atlas Energy, Inc. (“Atlas Energy”) (NASDAQ: ATLS). Atlas Energy’s focus is on the development and/or production of natural gas and oil in the Appalachian, Michigan, Illinois, and/or Colorado basin regions of the United States of America. Atlas Energy is also a leading sponsor of and manages tax-advantaged direct investment partnerships, in which it co-invests to finance the exploitation and development of its acreage. Atlas Energy Resource Services, Inc. provides Atlas Energy with the personnel necessary to manage its assets and raise capital.

On February 17, 2011, Atlas Pipeline Holdings, L.P. (“AHD”) (NYSE: AHD), a then-majority owned subsidiary of Atlas Energy and general partner to Atlas Pipeline Partners, L.P. (“APL”) (NYSE: APL), completed an acquisition of assets from Atlas Energy, which included its investment management business, proved reserves located in the Appalachian Basin, New Albany Shale, Antrim Shale, Chattanooga Shale and Niobrara formations, and other assets. As part of the transaction, Atlas Resources, LLC became an indirect subsidiary of AHD. Concurrent with the sale of assets by Atlas Energy to AHD, Atlas Energy and its subsidiaries completed a merger transaction with Chevron Corporation (“Chevron”), whereby Chevron acquired the assets of Atlas Energy in exchange for $38.25 per Atlas Energy share. Subsequent to the transaction, AHD changed its name to Atlas Energy, L.P.

We have drilled and currently operate wells located in New York, Pennsylvania and Tennessee. We have no employees and rely on our MGP for management, which in turn, relies on its parent company, Atlas Energy Holdings Operating Company, LLC for administrative services. See Item 11 “Executive Compensation.”

We received total cash subscriptions from investors of $70,883,000, which were paid to our MGP acting as operator and general drilling contractor under our drilling and operating agreements. Our MGP contributed leases, tangible equipment, and paid all syndication and offering costs for a total capital contribution of $24,307,100. We have drilled 256 developmental wells to the Clinton/Medina, Upper Devonian Sandstones and Southern Appalachia Shale geological formations in New York, Pennsylvania and Tennessee.

Our operating cash flows are generated from our wells, which produce natural gas and oil. Our produced natural gas and oil is then delivered to market through third-party gas gathering systems. The majority of our natural gas and oil is delivered into the Laurel Mountain Midstream, LLC (“Laurel Mountain”) gas gathering system, a joint venture between APL and the Williams Companies, Inc. (NYSE: WMB). Laurel Mountain owns and operates all of APL’s previously owned northern Appalachian assets. Upon formation of the joint venture in May 2009, Atlas Energy entered into a new gas gathering agreement with Laurel Mountain, whereby Atlas Energy remits to Laurel Mountain a range generally from $0.35 per thousand cubic feet (“Mcf”) to the amount of the competitive gathering fee (which is currently defined as 16% of the gross sales price received for our gas).

Our ongoing operating and maintenance costs have been and are expected to be fulfilled through revenues from the sale of our natural gas and oil production. We pay our MGP a monthly well supervision fee of $376 per well, as outlined in our drilling and operating agreement. This well supervision fee covers all normal and regularly recurring operating expenses for the production and sale of natural gas and oil, such as:

	•		well tending, routine maintenance and adjustment;

	•		reading meters, recording production, pumping, maintaining appropriate books and records; and

	•		preparation of reports for us and government agencies.

The well supervision fees, however, do not include costs and expenses related to the purchase of certain equipment, materials and brine disposal. If these expenses are incurred, we pay cost for third-party services, materials, and a reasonable charge for services performed directly by our MGP or its affiliates. Also, beginning one year after each of our wells has been placed into production our MGP, as operator, may retain $200 per month per well to cover the estimated future plugging and abandonment costs of the well. As of December 31, 2010, our MGP had not withheld any funds for this purpose.

Our wells will continue to produce until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. No other wells will be drilled and no additional funds will be required for drilling. See Item 2 “Properties” for information concerning our wells.

Markets and Competition.The availability of a ready market for natural gas and oil produced by us, and the price obtained, depends on numerous factors beyond our control, including the extent of domestic production, imports of foreign natural gas and oil, political instability or terrorist acts in oil and gas producing countries and regions, market demand, competition from other energy sources, the effect of federal regulation on the sale of natural gas and oil in interstate commerce, other governmental regulation of the production and transportation of natural gas and oil and the proximity, availability and capacity of pipelines and other required facilities. Our MGP is responsible for selling our natural gas production. Our natural gas is sold as discussed in Item 2 “Properties.” During 2010 and 2009, we experienced no problems in selling our natural gas and oil. Product availability and price are the principal means of competition in selling natural gas and oil production.

While it is impossible to accurately determine our comparative position in the industry, we do not consider our operations to be a significant factor in the industry. See Item 2 “Properties” regarding the marketing of our natural gas and oil.

Governmental Regulation.The energy industry, in general, is heavily regulated by federal and state authorities, including regulation of production, environmental quality and pollution control. The intent of federal and state regulations generally is to prevent waste, protect rights to produce natural gas and oil between owners in a common reservoir and control contamination of the environment. Failure to comply with regulatory requirements can result in substantial fines and other penalties. The following discussion of the regulation of the United States of America energy industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which our operations may be subject.

Regulation of oil and gas producing activities.State regulatory agencies, where a producing natural gas well is located provide a comprehensive statutory and regulatory scheme for oil and gas operations such as ours including supervising the production activities and the transportation of natural gas sold in intrastate markets. Our oil and gas operations in Pennsylvania are regulated by the Department of Environmental Resources, Division of Oil and Gas, our oil and gas operations in Tennessee are regulated by the Tennessee Department of Environment and Conservation and the Division of Geology and our oil and gas operations in New York are regulated by the New York Department of Environmental and Conservation and the Division of Geology.

Among other things, these regulations involve:

	•		new well permit and well registration requirements, procedures and fees;

	•		minimum well spacing requirements;

	•		restriction on well locations and underground gas storage;

	•		certain well site restoration, groundwater protection and safety measures;

	•		landowner notification requirements;

	•		certain bonding or other security measures;

	•		various reporting requirements;

	•		well plugging standards and procedures; and

	•		broad enforcement powers.

Environmental and Safety Regulation.Under the Comprehensive Environmental Response, Compensation and Liability Act, the Toxic Substances Control Act, the Resource Conservation and Recovery Act, the Oil Pollution Act of 1990, the Clean Air Act, and other federal and state laws relating to the environment, owners and operators of wells producing natural gas, or oil can be liable for fines, penalties and clean-up costs for pollution caused by the wells. Moreover, the owners or operators’ liability can extend to pollution costs from situations that occurred prior to their acquisition of the assets. State public utility regulators have either adopted federal standards or promulgated their own safety requirements consistent with the federal regulations.

We believe we have complied in all material respects with applicable federal and state regulations and do not expect that these regulations will have a material adverse impact on our operations. Our producing activities also must comply with various federal, state and local laws not mentioned, including those covering the discharge of materials into the environment or otherwise relating to the protection of the environment.

Where can you find more information.We file a Form 10-K Annual Report and Form 10-Q Quarterly Reports as well as other non-recurring special purpose reports with the Securities and Exchange Commission. A complete list of our filings is available on the Securities and Exchange Commission’s website at www.sec.gov. Any of our filings are also available at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The Public Reference Room may be contacted at 1-800- SEC-0330 for further information.

Additionally, our MGP will provide copies of any of these reports to you without charge. Such requests should be made to:

Atlas America Series 27-2006 L.P.
Westpointe Corporate Center One
1550 Coraopolis Heights Road, 2nd Floor
Moon Township, PA 15108


ITEM 2.		PROPERTIES

Drilling Activity.For the years ended December 31, 2010 and 2009, we did not drill any wells nor do we expect to do so in future years.

Summary of Producing Wells.The table below presents the number of producing gross and net wells at December 31, 2010, in which we have a working interest. All wells are located in the Appalachian Basin.


	Number of Producing Wells
	Gross		Net
Gas		250		200.61

Production.The following table presents the quantities of natural gas and oil we produced (net to our interest), our average sales price, and our average production (lifting) cost per equivalent unit of production for the period indicated.


									Average
Year									Production Cost
Ended	Production				Average Sales Price				(Lifting Cost)
December 31,	Oil (bbls) ⁽¹⁾		Gas (mcf) ⁽¹⁾		per bbl ^{(1) (3) (5)}		per mcf ^{(1) (3) (4)}		per mcfe ^{(1) (2)}
2010		1,600		696,900	$	72.86	$	6.60	$	2.55
2009		2,200		869,800	$	62.86	$	7.93	$	2.46


(1)		“Mcf” represents one thousand cubic feet of natural gas. “Mcfe” represents a thousand cubic feet equivalent. Oil production is converted to mcfe at the rate of six mcf per barrel (“bbl”).

(2)		Lifting costs include labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, property taxes, insurance and gathering charges.

(3)		Average sales prices represent accrual basis pricing after reversing the effect of previously recognized gains resulting from prior period impairment charges.

(4)		Average gas prices are calculated by including in total revenue derivative gains previously recognized into income and dividing by the total volume for the period. Previously recognized derivative gains were $661,500 and $2,163,200 for the years ended December 31, 2010 and 2009. The derivative gains are included in other comprehensive income and resulted from prior period impairment charges.

(5)		Average oil prices are calculated by including in total revenue derivative gains previously recognized into income and dividing by the total volume for the period. Previously recognized derivative gains were $32,100 and $56,100 for the years ended December 31, 2010 and 2009 the derivative gains are included in other comprehensive income and resulted from prior period impairment charges.

Natural Gas and Oil Reserve Information.In December 2008, the Securities and Exchange Commission (“SEC”) approved revisions to its oil and gas reporting disclosures by adopting amendments to Rule 4-10 of Regulation S-X and Items 201, 801, and 802 of Regulation S-K effective for fiscal years ending on or after December 31, 2009. These new disclosure requirements are referred to as “Modernization of Oil and Gas Reporting” and include provisions that:

	•		Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.

	•		Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end pricing. This should maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date.

	•		Permit companies to disclose their probable and possible reserves on a voluntary basis. Current rules limit disclosure to only proved reserves.

	•		Update and revise reserve definitions to reflect changes in the oil and gas industry and new technologies. New updated definitions include “by geographic area” and “reasonable certainty.”

	•		Permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.

	•		Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures are required related to internal controls over reserve estimation, as well as a report addressing the independence and qualifications of a company’s reserves preparer or auditor based on Society of Petroleum Engineers’ criteria.

The Partnership adopted these revised requirements December 31, 2009.

The following tables summarize information regarding our estimated proved natural gas and oil reserves as of the dates indicated. Proved reserves are the estimated quantities of crude oil and natural gas, which, by an analysis of geological and engineering data, can be estimated with reasonable certainty to be recoverable in future years from known reservoirs under existing economic conditions, operating methods and government regulations (i.e., prices and costs as of the date the estimate is made). Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. The estimated reserves include reserves attributable to our direct ownership interests in oil and gas properties. For the years ended December 31, 2010 and 2009, we based our estimates of proved reserves on the 12-month unweighted average price of the first-day-of-the-month price for each calendar month and then applied any basis and British Thermal Units (“btu”) differentials specifically applicable to each oil and gas property based on location and pricing details. The following table summarizes the natural gas and oil prices used in the estimation of proved reserves:


	December 31,
	2010		2009
Natural gas (per mcf)	$	4.38	$	3.87
Oil ( per bbl)		79.43		61.18

Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas and oil reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The preparation of our natural gas and oil reserve estimates were completed in accordance with our prescribed internal control procedures, which include verification of input data delivered to our third-party reserve specialist, as well as a multi-functional management review. For the year ended December 31, 2010, we retained Wright & Company, a third-party, independent petroleum engineering firm, to prepare a report of proved reserves. The reserves report included a detailed review of our properties. Wright & Company’s evaluation was based on more than 35 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations applicable as of December 31, 2010. The Wright & Company report, including the qualifications of the chief technical person responsible for the report, was prepared in accordance with generally accepted petroleum engineering and evaluation principles and is attached as Exhibit 99.1 to this Annual Report on Form 10-K. Results of production subsequent to the date of the estimate may justify revision of this estimate. Future prices received from the sale of natural gas and oil may be different from those estimated by our independent petroleum engineering firm in preparing their reports. The amounts and timing of future operating costs may also differ from those used. Accordingly, the reserves set forth in the following tables ultimately may not be produced and the proved undeveloped reserves may not be developed within the periods anticipated. You should not construe the estimated PV-10 and standardized measure values as representative of the current or future fair market value of our proved natural gas and oil properties. PV-10 and standardized measure values are based upon projected cash inflows, which do not provide for changes in natural gas and oil prices or for the escalation of expenses. The meaningfulness of these estimates depends upon the accuracy of the assumptions upon which they were based.

We evaluate natural gas reserves at constant temperature and pressure. A change in either of these factors can affect the measurement of natural gas reserves. We deducted when applicable, operating costs, development costs and production-related and ad valorem taxes in arriving at the estimated future cash flows. The following table presents our reserve information for the previous two years. We base the estimates on operating methods and conditions prevailing as of the dates indicated:


	At December 31,
	2010		2009

Natural gas reserves — proved developed reserves (Mcf)^{(1) (2) (4)}		4,385,700		5,894,900
Oil reserves — proved developed reserves (Bbl)^{(1) (2) (4)}		9,900		13,600

Total proved reserves (Mcfe)		4,445,100		5,976,500


PV-10 estimate of cash flows of proved reserves^(3) (4)	$	5,344,300	$	6,980,400

PV-10 estimate per limited partner unit⁽⁵⁾	$	1,270	$	1,657

Undiscounted estimate per limited partner unit⁽⁵⁾	$	1,962	$	2,715


(1)		“Proved reserves” generally refers to the estimated quantities of crude oil, and natural gas, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Reservoirs are considered proved if economic production is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes: that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data.

(2)		“Proved developed oil and gas reserves” generally refers to reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

(3)		The present value of estimated future net cash flows is calculated by discounting estimated future net cash flows by 10% annually.

(4)		Please see Regulation S-X rule 4-10 for complete definitions of each reserve category.

(5)		This value per $25,000 unit is determined by following the methodology used for determining our proved reserves using the data discussed above. However, this value does not necessarily reflect the fair market value of a unit, and each unit is illiquid. Also, the value of a unit for purposes of presentment of the unit to our MGP for purchase is different, because it is calculated under a formula set forth in the Partnership Agreement.

We have not filed any estimates of our gas and oil reserves with, nor were such estimates included in any reports to, any Federal or foreign governmental agency other than the SEC within the 12 months before the date of this filing.

Title to Properties. We believe that we hold good and indefeasible title to our properties in accordance with standards generally accepted in the natural gas industry, subject to exceptions stated in the opinions of counsel employed by us in the various areas in which we conduct our activities. We do not believe that these exceptions detract substantially from our use of any property. As is customary in the natural gas industry, our MGP conducts only a perfunctory title examination at the time it acquires a property. Before our MGP commences drilling operations, it conducts an extensive title examination and performs curative work on defects that it deems significant. Our MGP has obtained title examinations for substantially all of our producing properties. No single property represents a material portion of our holdings.

Our properties are subject to royalty, overriding royalty and other outstanding interests customary in the natural gas industry. Our properties are also subject to burdens such as liens incident to operating agreements, taxes, development obligations under natural gas and oil leases, farm-out arrangements and other encumbrances, easements and restrictions. We do not believe that any of these burdens will materially interfere with our use of our properties.

Acreage.The table below presents, by state, the estimated acres of developed oil and gas acreage in which we had an interest at December 31, 2010. There was no undeveloped acreage at December 31, 2010.


	Developed Acreage
Location	Gross ⁽¹⁾		Net ⁽²⁾
New York		131		131
Pennsylvania		3,872		3,363
Tennessee		2,399		1,680

Total		6,402		5,174


(1)		A “gross” acre is an acre in which we own a working interest.

(2)		A “net” acre represents the actual working interest we own in one gross acre divided by one hundred. For example, a 50% working interest in an acre is one gross acre, but a 0.5 net acre.

Delivery Commitments. Atlas Energy markets our natural gas supply, which is principally located in the Appalachian region, primarily to Colonial Energy, Inc., Atmos Energy Marketing LLC, Sequent Energy Management, Hess Corporation, NJR Energy Services, BP Energy, Exelon Energy, National Fuel Resources, Equitable Energy and to third-party natural gas purchasers or marketers. We are not required to provide any fixed and determinable quantities of gas under any agreement.

The pricing arrangements with Colonial Energy, Inc., Atmos Energy Marketing LLC, Sequent Energy Management, Hess Corporation, NJR Energy Services, BP Energy, Exelon Energy, National Fuel Resources, Equitable Energy and other third-party gas purchasers or marketers are tied to the New York Mercantile Exchange Commission, or NYMEX, spot market price. The total price received for our gas is a combination of the monthly NYMEX spot price plus a basis adjustment. For example, the NYMEX spot price is the base price and there is an additional premium paid because of the location of the gas (the Appalachian Basin) in relation to the gas market, which is referred to as the “basis.”

Pricing for natural gas and oil has been volatile and uncertain for many years. The agreements with Colonial Energy, Inc., Atmos Energy Marketing LLC, Sequent Energy Management, Hess Corporation, NJR Energy Services, BP Energy, Exelon Energy, National Fuel Resources, Equitable Energy and the other third-party gas purchasers or marketers also permit Atlas Energy and its affiliates to implement gas forward sales transactions through those companies. Colonial Energy, Inc., Atmos Energy Marketing LLC, Sequent Energy Management, Hess Corporation, NJR Energy Services, BP Energy, Exelon Energy, National Fuel Resources, Equitable Energy and the other third-party purchasers or marketers also use NYMEX based financial instruments to hedge their pricing exposure and make price-hedging opportunities available to Atlas Energy, which then makes those arrangements available to us and its other partnerships. The price paid by Colonial Energy, Inc., Atmos Energy Marketing LLC, Sequent Energy Management, Hess Corporation, NJR Energy Services, BP Energy, Exelon Energy, National Fuel Resources, Equitable Energy and any other third-party purchasers for certain volumes of natural gas sold under these hedge agreements may be significantly different from the underlying monthly spot market price. Also, Atlas Energy’s hedges may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. The futures contracts employed by Atlas Energy are commitments to purchase or sell natural gas at future dates and generally cover one-month periods for up to six years in the future. The overall portion of our natural gas and oil portfolio that is hedged changes from time to time.

To assure that all financial instruments will be used solely for hedging price risks, and not for speculative purposes, Atlas Energy has established a committee to assure that all financial trading is done in compliance with Atlas Energy’s hedging policies and procedures. Atlas Energy does not intend to contract for positions that it cannot offset with actual production.


ITEM 3.		LEGAL PROCEEDINGS

The MGP is not aware of any legal proceedings filed against us.

Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of their collective business. The MGP management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the MGP’s financial condition or results of operations.


ITEM 4.		(REMOVED AND RESERVED)

None

PART II


ITEM 5.		MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED SECURITY HOLDER MATTERS

Market Information.There is no established public trading market for our units and we do not anticipate a market for our units will develop. Our units may be transferred only in accordance with the provisions of Article VI of our Partnership Agreement which requires:

	•		our managing general partner consent;

	•		the transfer not result in materially adverse tax consequences to us; and

	•		the transfer not violate federal or state securities laws.

An assignee of a unit may become a substituted partner only upon meeting the following conditions:

	•		the assignor gives the assignee the right;

	•		our MGP consents to the substitution;

	•		the assignee pays to us all costs and expenses incurred in connection with the substitution; and

	•		the assignee executes and delivers the instruments, which our MGP requires to effect the substitution and to confirm his or her agreement to be bound by the terms of our partnership agreement.

A substitute partner is entitled to all of the rights of full ownership of the assigned units, including the right to vote.

Holders.As of December 31, 2010, we had 1,379 unit holders.

Distributions.Our MGP reviews our accounts monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any. We distribute those funds, which our MGP determines are not necessary for us to retain, to our partners. We will not advance or borrow funds for purposes of making distributions.

The determination of our revenues and costs is made in accordance with generally accepted accounting principles, consistently applied, and cash distributions to our MGP may only be made in conjunction with distributions to our limited partners.

During the year ended December 31, 2010 and 2009, we distributed the following:

•

$2,807,900 and $4,805,900 to our limited partners; and

•

$541,800 and $1,183,200 to our managing general partner, respectively.


ITEM 7.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION OR PLAN OF OPERATIONS

The following discussion provides information to assist in understanding our financial condition and result of operations. This discussion should be read in conjunction with our financial statements and related notes appearing elsewhere in this report.

We are a Delaware limited partnership, formed on July 21, 2006 with Atlas Resources, LLC, serving as our Managing General Partner (Atlas Resources or “MGP”). Atlas Resources, LLC is an indirect subsidiary of Atlas Energy, Inc. (“Atlas Energy”) (NASDAQ: ATLS). Atlas Energy’s focus is on the development and/or production of natural gas and oil in the Appalachian, Michigan, Illinois, and/or Colorado basin regions of the United States of America. Atlas Energy is also a leading sponsor of and manages tax-advantaged direct investment partnerships, in which it co-invests to finance the exploitation and development of its acreage. Atlas Energy Resource Services, Inc. provides Atlas Energy with the personnel necessary to manage its assets and raise capital.

Results of Operations.The following table sets forth information related to our production revenues, volumes, sales prices, production costs and depletion during the periods indicated:


	Years Ended December 31,
	2010			2009
Production revenues (in thousands):
Gas	$	3,939		$	4,733
Oil		82			79

Total	$	4,021		$	4,812

Production volumes:
Gas (mcf/day)⁽¹⁾		1,909			2,383
Oil (bbls/day)⁽¹⁾		4			6

Total (mcfe/day)⁽¹⁾		1,933			2,419

Average sales prices:⁽²⁾
Gas (per mcf)^{(1) (3)}	$	6.60		$	7.93
Oil (per bbl)^{(1) (4)}	$	72.86		$	62.86

Average production costs:
As a percent of revenues		45	%		45	%
Per mcfe⁽¹⁾	$	2.55		$	2.46

Depletion per mcfe	$	2.59		$	2.35


(1)		“Mcf” represents thousand cubic feet, “mcfe” represents thousand cubic feet equivalent and “bbls” represents barrels. Bbls are converted to mcfe using the ratio of six mcfs to one bbl.

(2)		Average sales prices represent accrual basis pricing after reversing the effect of previously recognized gains resulting from prior period impairment charges.

(3)		Average gas prices are calculated by including in total revenue derivative gains previously recognized into income and dividing by the total volume for the period. Previously recognized derivative gains were $661,500 and $2,163,200 for the years ended December 31, 2010 and 2009. The derivative gains are included in other comprehensive income and resulted from prior period impairment charges.

(4)		Average oil prices are calculated by including in total revenue derivative gains previously recognized into income and dividing by the total volume for the period. Previously recognized derivative gains were $32,100 and $56,100 for the years ended December 31, 2010 and 2009 the derivative gains are included in other comprehensive income and resulted from prior period impairment charges.

Natural Gas Revenues.Our natural gas revenues were $3,939,400 and $4,733,400 for the years ended December 31, 2010 and 2009, respectively, a decrease of $794,000 (17%). The $794,000 decrease in natural gas revenues for the year ended December 31, 2010 as compared to the prior year period was attributable to a $941,200 decrease in production volumes partially offset a $147,200 increase in natural gas sales prices after the effect of financial hedges which were driven by market conditions. Our production volumes decreased to 1,909 mcf per day for the year ended December 31, 2010 from 2,383 mcf per day for the year ended December 31, 2009, a decrease of 474 mcf per day (20%). The overall decrease in natural gas production volumes for the year ended December 31, 2010 resulted primarily from the normal decline inherent in the life of a well.

The price we receive for our natural gas is primarily a result of the index-driven agreements with Colonial Energy, Inc., Atmos Energy Marketing LLC, Sequent Energy Management, Hess Corporation, NJR Energy Services, BP Energy, Exelon Energy, National Fuel Resources, Equitable Energy and our other natural gas purchasers. See Item 2 “Properties.” Thus, the price we receive for our natural gas may vary significantly each month as the underlying index changes in response to market conditions.

Oil Revenues. We drill wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $82,000 and $79,100 for the years ended December 31, 2010 and 2009, respectively, an increase of $2,900 (4%). The $2,900 increase in oil revenues for the years ended December 31, 2010 as compared to the prior year period was attributable to a $24,400 increase in oil prices, which were driven by market conditions partially offset by a $21,500 decrease in production volumes. Our average price we received for our oil increased to $72.86 per bbl for the year ended December 31, 2010 as compared to $62.86 per bbl for the year ended December 31, 2009, an increase of $10.00 per bbl (16%), this increase is driven by market conditions. Our production volumes were decreased to 4 bbls per day for the year ended December 31, 2010 from 6 bbls per day for the year ended December 31 2009, a decrease of 2 bbls per day (33%).

Expenses.Production expenses were $1,803,800 and $2,175,000 for the years ended December 31, 2010 and 2009, respectively, a decrease of $371,200 (17%). The decrease for the year ended December 31, 2010 was primarily due to lower transportation expenses, which were affected by a decrease in production volumes.

Depletion expense as a percentage of oil and gas revenues was 45% for the year ended December 31, 2010 as compared to 43% for the year ended December 31, 2009. These percentage changes are directly attributable to changes in revenues, oil and gas reserve quantities, product prices, production volumes and changes in the depletable cost basis of our oil and gas properties.

Impairment of oil and gas properties for the year ended December 31, 2010 was $5,196,300. There was no impairment for the year ended December 31, 2009. Annually, we compare the carrying value of our proved developed oil and gas producing properties to their estimated fair market value. To the extent our carrying value exceeds the estimated fair market value an impairment charge is recognized. This impairment charge is based on reserve quantities, future market values and our carrying value. We cannot provide any assurance that similar charges may or may not be taken in future periods.

General and administrative expenses for the years ended December 31, 2010 and 2009 were $212,900 and $217,600, respectively, a decrease of $4,700 (2%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP and vary from period to period due to the timing and billing of the costs and services provided by the partnership.

Liquidity and Capital Resources.Cash provided by operating activities decreased $2,472,700 in the year ended December 31, 2010 to $3,232,200 as compared to $5,704,900 for the year ended December 31, 2009. This decrease was primarily due to a decrease in net earnings before depletion, net non-cash loss on derivative value, impairment and accretion of $1,940,900. This decrease was also due to the change in accounts receivable-affiliate which decreased operating cash flows by $385,100 in the year ended December 31, 2010 as compared to the year ended December 31, 2009.

Cash used in financing activities decreased $2,639,400 during the year ended December 31, 2010 to $3,349,700 from $5,989,100 for the year ended December 31, 2009. This decrease was due to a decrease in cash distributions to partners.

Our MGP may withhold funds for future plugging and abandonment costs. Through December 31, 2010, our MGP had not withheld any funds for this purpose. Any additional funds, if required, will be obtained from production revenues or borrowings from our MGP or its affiliates, which are not contractually committed to make loans to us. The amount that we may borrow may not at any time exceed 5% of our total subscriptions, and we will not borrow from third-parties.

The Partnership is generally limited to the amount of funds generated by the cash flows from our operations, which we believe is adequate to fund future operations and distributions to our partners. Historically, there has been no need to borrow funds from our MGP to fund operations.

Critical Accounting Policies

Use of estimates.The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include depletion and depreciation, asset impairment, fair value of derivative instruments, and the probability of forecasted transactions. We summarize our significant accounting policies within our financial statements included in Item 8, “Financial Statements.” The critical accounting policies and estimates we have identified are discussed below.

Impairment of Long-Lived Assets.The cost of oil and gas properties, less estimated salvage value, is depleted on the units-of-production method and is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. Events or changes in circumstances that would indicate the need for impairment testing include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States of America and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. During 2010, we recognized an impairment charge of $5,196,300, net of an offsetting gain in other comprehensive income of $326,800. During 2009 we did not recognize an impairment charge.

Fair Value of Financial Instruments

We have established a hierarchy to measure our financial instruments at fair value which requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1 —Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2 —Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3— Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

Our MGP uses a fair value methodology to value the assets and liabilities for our outstanding derivative contracts. The commodity hedges are calculated based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements.

Assets and liabilities that are required to be measured at fair value on a nonrecurring basis include our oil and gas properties and asset retirement obligations (“ARO’s”) that are defined as Level 3. Estimates of the fair value of ARO’s are based on discounted cash flows using numerous estimates, assumptions, and judgments regarding the cost, timing of settlement, our credit-adjusted risk-free rate and inflation rates.

Reserve Estimates.Our estimates of proved natural gas and oil reserves and future net revenues from them are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Any significant variance in these assumptions could materially affect the estimated quantity of our reserves. As a result, our estimates of proved natural gas and oil reserves are inherently imprecise. Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves may vary substantially from our estimates or estimates contained in the reserve reports and may affect partnership distributions. In addition, our proved reserves may be subject to downward or upward revision based upon production history, results of future development, prevailing natural gas and oil prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control.

Asset Retirement Obligations. On an annual basis, we estimate the costs of future dismantlement, restoration, reclamation and abandonment of our operating assets. We also estimate the salvage value of equipment recoverable upon abandonment. Projecting future retirement cost estimates is difficult as it involves the estimation of many variables such as economic recoveries of reserves, future labor and equipment rates, future inflation rates and a credit adjusted risk free rate. To the extent future revisions to these assumptions impact the fair value of our existing asset retirement obligation, a corresponding adjustment is made to our oil and gas properties. A decrease in salvage values or an increase in dismantlement, restoration, reclamation and abandonment costs from those we have estimated, or changes in their estimates or costs, could reduce our gross profit from operations.

Working Interest.Our Partnership Agreement establishes that revenues and expenses will be allocated to our MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). Our MGP is also provided an additional working interest of 7% as provided in our agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expenses until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership. As of December 31, 2010, $63,800 of net earnings resulting from the working interest adjustment was reclassified from the MGP’s capital account to the limited partner’s capital account.


ITEM 8.		FINANCIAL STATEMENTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of
Atlas America Series #27-2006 L.P.

We have audited the accompanying balance sheets of Atlas America Series #27-2006 L.P. (a Delaware Limited Partnership) as of December 31, 2010 and 2009, and the related statements of operations, comprehensive (loss) income, changes in partners’ capital, and cash flows for the years then ended. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Atlas America Series #27-2006 L.P. as of December 31, 2010 and 2009, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Cleveland, Ohio
March 30, 2011

ATLAS AMERICA SERIES 27-2006 L.P.
BALANCE SHEETS
DECEMBER 31,


	2010		2009
ASSETS
Current assets:
Cash and cash equivalents	$	260,100	$	377,600
Accounts receivable-affiliate		806,100		1,449,900
Short-term hedge receivable due from affiliate		754,600		856,100

Total current assets		1,820,800		2,683,600

Oil and gas properties, net		11,056,400		17,705,800
Long-term hedge receivable due from affiliate		737,400		704,300

	$	13,614,600	$	21,093,700


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	13,900	$	59,000
Short-term hedge liability due to affiliate		5,500		10,300

Total current liabilities		19,400		69,300

Asset retirement obligation		3,005,700		2,235,500
Long-term hedge liability due to affiliate		128,500		107,300

Partners’ capital:
Managing general partner		2,399,500		4,080,200
Limited partners (2,840 units)		7,682,100		14,504,000
Accumulated other comprehensive income		379,400		97,400

Total partners’ capital		10,461,000		18,681,600

	$	13,614,600	$	21,093,700

See accompanying notes to financial statements.

ATLAS AMERICA SERIES 27-2006 L.P.
STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2010 and 2009


	2010			2009
REVENUES
Natural gas and oil	$	4,021,400		$	4,812,500

Total revenues		4,021,400			4,812,500

COSTS AND EXPENSES
Production		1,803,800			2,175,000
Depletion		1,827,200			2,072,000
Impairment of oil and gas properties		5,196,300			—
Accretion of asset retirement obligations		134,100			120,800
General and administrative		212,900			217,600

Total expenses		9,174,300			4,585,400

Net (loss) earnings	$	(5,152,900	)	$	227,100


Allocation of net (loss) earnings:
Managing general partner	$	(588,000	)	$	400,600

Limited partners	$	(4,564,900	)	$	(173,500	)

Net loss per limited partnership unit	$	(1,607	)	$	(61	)

See accompanying notes to financial statements.

ATLAS AMERICA SERIES 27-2006 L.P.
STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009


	2010			2009

Net (loss) earnings	$	(5,152,900	)	$	227,100
Other comprehensive income:
Unrealized holding gain on hedging contracts		989,700			412,900
Less: reclassification adjustment for gains realized in net (loss) earnings		(707,700	)		(315,500	)

Total other comprehensive income		282,000			97,400

Comprehensive (loss) income	$	(4,870,900	)	$	324,500

See accompanying notes to financial statements.

ATLAS AMERICA SERIES 27-2006 L.P.
STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL
FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009


							Accumulated
	Managing						Other
	General			Limited			Comprehensive
	Partner			Partners			Income		Total

Balance at December 31, 2008	$	5,760,400		$	18,595,300		$	—	$	24,355,700

Participation in revenue and costs and expenses
Net production revenues		859,800			1,777,700			—		2,637,500
Depletion		(348,900	)		(1,723,100	)		—		(2,072,000	)
Accretion of asset retirement obligations		(39,400	)		(81,400	)		—		(120,800	)
General and administrative		(70,900	)		(146,700	)		—		(217,600	)

Net earnings (loss)		400,600			(173,500	)		—		227,100

MGP asset returned		(9,500	)		—			—		(9,500	)

Other comprehensive income		—			—			97,400		97,400

Subordination		(888,100	)		888,100			—		—

Distributions to partners		(1,183,200	)		(4,805,900	)		—		(5,989,100	)


Balance at December 31, 2009	$	4,080,200		$	14,504,000		$	97,400	$	18,681,600

Participation in revenue and costs and expenses
Net production revenues		721,500			1,496,100			—		2,217,600
Depletion		(311,300	)		(1,515,900	)		—		(1,827,200	)
Impairment of oil and gas properties		(885,300	)		(4,311,000	)		—		(5,196,300	)
Accretion of asset retirement obligations		(43,600	)		(90,500	)		—		(134,100	)
General and administrative		(69,300	)		(143,600	)		—		(212,900	)

Net loss		(588,000	)		(4,564,900	)		—		(5,152,900	)

Other comprehensive income		—			—			282,000		282,000

Subordination		(487,100	)		487,100			—		—

Working interest adjustment		(63,800	)		63,800			—		—

Distributions to partners		(541,800	)		(2,807,900	)		—		(3,349,700	)


Balance at December 31, 2010	$	2,399,500		$	7,682,100		$	379,400	$	10,461,000

See accompanying notes to financial statements.

ATLAS AMERICA SERIES 27-2006 L.P.
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009


	2010			2009
Cash flows from operating activities:
Net (loss) earnings	$	(5,152,900	)	$	227,100
Adjustments to reconcile net (loss) earnings to net cash provided by operating activities:
Depletion		1,827,200			2,072,000
Non-cash loss on derivative		366,800			2,219,300
Impairment of oil and gas properties		5,523,100			—
Accretion of asset retirement obligation		134,100			120,800
Decrease in accounts receivable-affiliate		643,800			1,028,900
(Decrease) increase in accrued liabilities		(45,100	)		36,800
Asset retirement obligation settled		(64,800	)		—

Net cash provided by operating activities		3,232,200			5,704,900

Cash flows from financing activities:
Distributions to partners		(3,349,700	)		(5,989,100	)

Net cash used in financing activities		(3,349,700	)		(5,989,100	)


Net decrease in cash and cash equivalents		(117,500	)		(284,200	)
Cash and cash equivalents at beginning of period		377,600			661,800

Cash and cash equivalents at end of period	$	260,100		$	337,600


Supplemental Schedule of non-cash investing and financing activities:

Assets contributed by (returned to) the managing general partner:
Tangible equipment	$	—		$	(19,100	)
Intangible drilling costs		—			9,600

Total assets returned to the managing general partner	$	—		$	(9,500	)


Asset retirement obligation revision	$	700,900		$	101,700

See accompanying notes to financial statements.

ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009

NOTE 1 — DESCRIPTION OF BUSINESS

Atlas America Series 27-2006 L.P. (the “Partnership”) is a Delaware limited partnership, formed on July 21, 2006 with Atlas Resources, LLC serving as its Managing General Partner and Operator (Atlas Resources or “MGP”). Atlas Resources, LLC is an indirect subsidiary of Atlas Energy, Inc. (“Atlas Energy”) (NASDAQ: ATLS). Atlas Energy’s focus is on the development and/or production of natural gas and oil in the Appalachian, Michigan, Illinois, and/or Colorado basin regions of the United States of America. Atlas Energy is also a leading sponsor of and manages tax-advantaged direct investment partnerships, in which it co-invests to finance the exploitation and development of its acreage. Atlas Energy Resource Services, Inc. provides Atlas Energy with the personnel necessary to manage its assets and raise capital.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. Management has considered for disclosure any material subsequent events through the date the financial statements were issued.

Use of Estimates

The preparation of the Partnership’s financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, asset impairments, fair value of derivative instruments, and the probability of forecasted transactions. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions as much as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the years ended December 31, 2010 and 2009 represent actual results in all material respects (see “Revenue Recognition” accounting policy for further description).

Accounts Receivable and Allowance for Possible Losses

In evaluating the need for an allowance for possible losses, the MGP performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by review of its customers’ credit information. Credit is extended on an unsecured basis to many of its energy customers. At December 31, 2010 and 2009, the Partnership’s MGP’s credit evaluation indicated that the Partnership had no need for an allowance for possible losses.

ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2010 AND 2009

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Fair Value of Financial Instruments

The carrying amounts of the Partnership’s cash and receivables approximate fair values because of the short maturities of these instruments.

Supplemental Cash Flow Information

The Partnership considers temporary investments with a maturity at the date of acquisition of 90 days or less to be cash equivalents. No cash was paid by the Partnership for interest or income taxes for the years ended December 31, 2010 and 2009.

Concentration of Credit Risk

Financial instruments, which potentially subject the Partnership to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Partnership places its temporary cash investments in deposits with high-quality financial institutions. At December 31, 2010, the Partnership had $280,000 in deposits at one bank, none of which was over the insurance limit of the Federal Deposit Insurance Corporation, and at December 31, 2009, the Partnership had $400,600 in deposits at one bank, none of which was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments.

Oil and Gas Properties

Oil and gas properties are stated at cost. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized. The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Oil is converted to gas equivalent basis (“Mcfe”) at the rate of one barrel equals 6 Mcf.

The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of developed producing properties. Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost from the property accounts and the resultant gain or loss is reclassified to the Partnership’s Statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its balance sheets. As a result of retirements, the Partnership reclassified $880,700 for the year ended December 31, 2010 from oil and gas properties to accumulated depletion.

Impairment of Long-Lived Assets

The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2010 AND 2009

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Impairment of Long-Lived Assets (Continued)

The review of the Partnership’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.

During the year ended December 31, 2010, the Partnership recognized $5,196,300 asset impairment related to oil and gas properties, net of an offsetting gain in accumulated other comprehensive income of $326,800. During the year ended December 31, 2009, the Partnership did not recognize an asset impairment. This impairment related to the carrying amount of these oil and gas properties being in excess of its estimate of their fair value at December 31, 2010. The estimate of fair value of these oil and gas properties was impacted by, among other factors, the deterioration of natural gas prices.

Working Interest

The Partnership Agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). The MGP is also provided an additional working interest of 7% as provided in the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expenses until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership. As of December 31, 2010, $63,800 of net earnings resulting from the working interest adjustment was reclassified from the MGP’s capital account to the limited partner’s capital account.

Revenue Recognition

The Partnership generally sells natural gas and crude oil at prevailing market prices. Revenue is recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil in which the Partnership has an interest with other producers are recognized on the basis of the Partnership’s percentage ownership of working interest. Generally, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index with certain adjustments based on proximity to gathering and transmission lines and the quality of its natural gas.

ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2010 AND 2009

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Revenue Recognition (Continued)

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation fees which are, in turn, based upon applicable product prices (see “Use of Estimates” accounting policy for further description). The Partnership had unbilled revenues at December 31, 2010 and 2009 of $582,900 and $1,052,100, respectively, which are included in accounts receivable — affiliate within the Partnership’s balance sheets.

Asset Retirement Obligation

The Partnership recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities, or asset retirement obligations (see Note 5). The Partnership recognizes a liability for future asset retirement obligations in the current period if a reasonable estimate of the fair value of the liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset.

Environmental Matters

The Partnership is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Partnership has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.

Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. Atlas Energy maintains insurance that may cover in whole or in part, certain environmental expenditures. For the years ended December 31, 2010 and 2009, the Partnership had no environmental matters requiring specific disclosure or the recording of a liability.

Comprehensive (Loss) Income

Comprehensive (loss) income includes net (loss) earnings and all other changes in equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States of America, have not been recognized in the calculation of net (loss) earnings. These changes, other than net (loss) earnings, are referred to as “other comprehensive income,” and for the Partnership include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges.

ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2010 AND 2009

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Recently Adopted Accounting Standards

In April 2010, the FASB issued Accounting Standards Update 2010-14, “Accounting for Extractive Industries — Oil & Gas: Amendments to Paragraph 932-10-S99-1” (“Update 2010-14”). Update 2010-14 provides amendments to add the SEC’s Regulation S-X Rule 4-10, “Financial Accounting and Reporting for Oil and Gas Producing Activities Pursuant to the Federal Securities Laws and the Energy Policy and Conservation Act of 1975” (“S-X Rule 4-10”) to Accounting Standards Codification (“ASC”) Topic 932 “Extractive Activities — Oil and Gas”. S-X Rule 4-10 was included in the SEC’s Final Rule, “Modernization of Oil and Gas Reporting, which became effective January 1, 2010. As Update 2010-14 only served to align the FASB’s ASC Topic 932 with the SEC’s S-X Rule 4-10, its adoption did not have a material impact on the Partnership’s financial position, results of operations or related disclosures.

In February 2010, the FASB issued Accounting Standards Update 2010-09, “Subsequent Events (Topic 855): Amendments to Certain Recognition and Disclosure Requirements” (“Update 2010-09”). Update 2010-09 removes the requirement for an SEC filer to disclose a date through which subsequent events have been evaluated in both issued and revised financial statements. Revised financial statements include financial statements revised as a result of either correction of an error or retrospective application of U.S. generally accepted accounting standards. The requirements of Update 2010-09 were effective upon its issuance on February 24, 2010. The requirements of Update 2010-09 were applied upon its adoption, and it did not have an impact on the Partnership financial position, results of operations or related disclosures.

In January 2010, the FASB issued Accounting Standards Update 2010-06, “Fair Value Measurement and Disclosures (Topic (820) — Improving Disclosures about Fair Value Measurement” (“Update 2010-06”). Update 2010-06 clarifies and requires new disclosures about the transfer of amounts between Level 1 and Level 2, as well as significant transfers in and out of Level 3. In addition, for Level 2 and Level 3 measurements, Update 2010-06 requires additional disclosure about the valuation technique used or any changes in technique. Update 2010-06 also clarifies that entities must disclose fair value measurements by classes of assets and liabilities, based on the nature and risks of the assets and liabilities. The requirements of Update 2010-06 are effective at the start of a reporting entity’s first fiscal year beginning after December 15, 2009 (January 1, 2010 for the Partnership). The requirements of Update 2010-06 were applied upon its adoption on January 1, 2010 and it did not have a material impact on the Partnership’s financial position, results of operations or related disclosures.

Major Customers

The Partnership’s natural gas is sold under contract to various purchasers. For the year ended December 31, 2010, sales to Atmos Energy Marketing LLC, Equitable Gas, South Jersey Resources Group LLC, Eagle Energy Partners and Sequent Energy Management accounted for 19%, 18%, 13%, 11% and 10% respectively, of total revenues. For the year ended December 31, 2009, sales to Atmos Energy Marketing LLC, Equitable Gas, Dominion Field Services, Inc. and South Jersey Resources Group LLC accounted for 17%, 17%, 15% and 10% respectively, of total revenues. No other customers accounted for 10% or more of total revenues for the years ended December 31, 2010 and 2009.

Income Taxes

The Partnership is not treated as a taxable entity for federal income tax purposes. Any item of income, gain, loss, deduction or credit flows through to the partners as though each partner had incurred such item directly. As a result, each partner must take into account their pro rata share of all items of partnership income and deductions in computing their federal income tax liability.

ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2010 AND 2009

NOTE 3 — PARTICIPATION IN REVENUES AND COSTS

The MGP and the limited partners will generally participate in revenues and costs in the following manner:


	Managing
	General			Limited
	Partner			Partners
Organization and offering costs		100	%		0	%
Lease costs		100	%		0	%
Revenues (1)		32.54	%		67.46	%
Operating costs, administrative costs, direct costs and all other operating costs (2)		32.54	%		67.46	%
Intangible drilling costs		4.81	%		95.19	%
Tangible equipment costs		60.07	%		39.93	%


(1)		Subject to the MGP’s subordination obligation, substantially all partnership revenues will be shared in the same percentage as capital contributions are to the total partnership capital contributions, except that the MGP will receive an additional 7% of the partnership revenues and the MGP revenue percentage may not exceed 40%.

(2)		These costs will be charged to the partners in the same ratio as the related production revenues are credited.

NOTE 4 — OIL AND GAS PROPERTIES

The following is a summary of oil and gas properties:


	December 31,			December 31,
	2010			2009
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	1,687,400		$	1,716,900
Wells and related equipment		86,251,900			86,402,200

		87,939,300			88,119,100

Accumulated depletion		(76,882,900	)		(70,413,300	)

	$	11,056,400		$	17,705,800

NOTE 5 — ASSET RETIREMENT OBLIGATION

The Partnership recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. It also recognizes a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depletion.

The estimated liability is based on the MGP’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its oil and gas properties, the Partnership has determined that there are no other material retirement obligations associated with tangible long-lived assets.

ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2010 AND 2009

NOTE 5 — ASSET RETIREMENT OBLIGATION (continued)

A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows:


	December 31,
	2010			2009
Asset retirement obligation at beginning of year	$	2,235,500		$	2,013,000
Revision in estimates		700,900			101,700
Liabilities settled		(64,800	)		—
Accretion expense		134,100			120,800

Asset retirement obligation at end of year	$	3,005,700		$	2,235,500

NOTE 6 — DERIVATIVE INSTRUMENTS

The MGP on behalf of the Partnership uses a number of different derivative instruments, principally swaps, collars and options, in connection with its commodity price risk management activities. The MGP enters into financial instruments to hedge its forecasted natural gas and crude oil sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas and crude oil is sold. Under swap agreements, the MGP receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas and crude oil at a fixed price for the relevant contract period.

The MGP formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity derivative contracts to the forecasted transactions. The MGP assesses, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the MGP will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by the MGP through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations. For derivatives qualifying as hedges, the Partnership recognizes the effective portion of changes in fair value in partners’ capital as accumulated other comprehensive income and reclassifies the portion relating to commodity derivatives to gas and oil production revenues for the Partnership’s derivatives within the Partnership’s statements of operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognizes changes in fair value within gain (loss) on mark-to-market derivatives in its statements of operations as they occur.

Derivatives are recorded on the Partnership’s balance sheets as assets or liabilities at fair value. The Partnership reflected a net derivative asset on its balance sheets of $1,358,000 at December 31, 2010, however unrealized gain of $978,600 recognized in income results in a net accumulated other comprehensive income balance of $379,400. The unrealized gain of $978,600 is comprised of $326,800 and $651,800 from 2010 and 2008 impairments, respectively. Of the remaining $379,400 net unrealized gain in accumulated other comprehensive income at December 31, 2010, if the fair values of the instruments remain at current market values, the Partnership will reclassify $240,300 of gains to the Partnership’s statements of operations over the next twelve month period as these contracts expire. Aggregate gains of $139,100 will be reclassified to the Partnership’s statements of operations in later periods as these remaining contracts expire. Actual amounts that will be reclassified will vary as a result of future price changes.

ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2010 AND 2009

NOTE 6 — DERIVATIVE INSTRUMENTS (Continued)

The following table summarizes the fair value of the Partnership’s derivative instruments as of December 31, 2010 and 2009, as well as the gain or loss recognized in the Statements of operations for effective derivative instruments for the years ended December 31, 2010 and 2009:

Fair Value of Derivative Instruments:


		Asset Derivatives					Liability Derivatives
Derivatives in		Fair Value					Fair Value
Cash Flow	Balance Sheet	December 31,		December 31,		Balance sheet	December 31,			December 31,
Hedging Relationships	Location	2010		2009		Location	2010			2009

Commodity Contracts	Current Assets	$	754,600	$	856,100	Current liabilities	$	(5,500	)	$	(10,300	)
	Long-Term Assets		737,400		704,300	Long-term liabilities		(128,500	)		(107,300	)


Total Derivatives		$	1,492,000	$	1,560,400		$	(134,000	)	$	(117,600	)

Effects of Derivative Instruments on Statement of Operations:

Gain

Recognized in OCI on Derivative

Reclassified from OCI into Net (Loss) Income

(Effective Portion)

Location of Gain

(Effective Portion)

Derivatives in

Twelve Months Ended

Reclassified from Accumulated

Twelve Months Ended

Cash Flow

December 31,

OCI into (Loss) Income

December 31,

Hedging Relationships

2010

2009

(Effective Portion)

2010

2009

Commodity Contracts

989,700

412,900

Natural Gas and Oil Revenue

707,700

315,500

The MGP enters into natural gas and crude oil future option contracts and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in natural gas and oil prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.

In December 2010, the MGP, on behalf of the Partnership, received approximately $4,100 in net proceeds from the early settlement of natural gas derivative positions for production periods during 2012. The gain realized upon the early terminations of these derivative positions is reported in accumulated other comprehensive income and will be reclassified to the Partnership’s Statements of operations in the same periods in which the hedged production revenues would have been recognized in earnings. The $4,100 in net proceeds is recorded in the hedge receivable balance on the Partnership’s balance sheet at December 31, 2010.

ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2010 AND 2009

NOTE 6 — DERIVATIVE INSTRUMENTS (Continued)

As of December 31, 2010, Atlas Energy had allocated to the Partnership the following natural gas and oil volumes hedged:

Natural Gas Fixed Price Swaps


Production			Average
Period Ending	Volumes		Fixed Price		Fair Value
December 31,	(MMbtu) ⁽¹⁾		(per MMbtu) ⁽¹⁾		Asset⁽²⁾

2011		217,200	$	6.964	$	532,100
2012		122,200		7.485		291,900
2013		79,300		6.803		110,000
2014		37,100		5.942		14,700

					$	948,700

Natural Gas Costless Collars


Production				Average
Period Ending	Option	Volumes		Floor & Cap		Fair Value
December 31,	Type	(MMbtu) ⁽¹⁾		(per MMbtu) ⁽¹⁾		Asset/(Liability)⁽²⁾

2011	Puts purchased		106,200	$	6.535	$	221,800
2011	Calls sold		106,200		7.653		(2,700	)
2012	Puts purchased		65,600		6.102		98,600
2012	Calls sold		65,600		7.328		(16,600	)
2013	Puts purchased		111,200		5.862		160,500
2013	Calls sold		111,200		7.043		(70,800	)
2014	Puts purchased		38,500		5.705		54,700
2014	Calls sold		38,500		6.811		(36,100	)

						$	409,400

Crude Oil Fixed Price Swaps


Production			Average
Period Ending	Volumes		Fixed Price		Fair Value
December 31,	(Bbl) ⁽¹⁾		(per Bbl) ⁽¹⁾		Liability⁽³⁾

2011		200	$	87.703	$	(1,400	)
2012		200		87.299		(1,200	)
2013		100		87.632		(300	)
2014		—		—		—

					$	(2,900	)

ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2010 AND 2009

NOTE 6 — DERIVATIVE INSTRUMENTS (Continued)

Crude Oil Costless Collars


Production				Average
Period Ending	Option	Volumes		Floor & Cap		Fair Value
December 31,	Type	(Bbl) ⁽¹⁾		(per Bbl) ⁽¹⁾		Asset/(Liability) ⁽³⁾

2011	Puts purchased		200	$	76.818	$	300
2011	Calls sold		200		100.965		(900	)
2012	Puts purchased		100		76.143		700
2012	Calls sold		100		101.596		(1,200	)
2013	Puts purchased		50		76.148		200
2013	Calls sold		50		102.587		(400	)
2014	Puts purchased		—		—		—
2014	Calls sold		—		—		—

						$	(1,300	)


				Total Net Asset		$	1,353,900


(1)		MMBTU represents million British Thermal Units. “Bbl” represents barrels.

(2)		Fair value based on forward NYMEX natural gas prices, as applicable.

(3)		Fair value based on forward WTI crude oil prices, as applicable.

NOTE 7 — FAIR VALUE OF FINANCIAL INSTRUMENTS

The Partnership has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value.

	Level 1 —		Unadjusted quoted prices in active markets for identical unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

	Level 2 —		Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

	Level 3 —		Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity, but rather through particular valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Partnership uses a fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 6). The Partnership’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements.

ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2010 AND 2009

NOTE 7 — FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

The Partnership estimates the fair value of asset retirement obligations using Level 3 inputs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements; the credit-adjusted risk-free rate of the Partnership; and estimated inflation rates (see Note 5).

NOTE 8 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The Partnership has entered into the following significant transactions with its MGP and its affiliates as provided under the Partnership agreement:

	•		Administrative costs which are included in general and administrative expenses in the Partnership’s statements of operations are payable at $75 per well, per month. Administrative costs incurred for the years ended December 31, 2010 and 2009 were $165,600 and $170,700, respectively.

	•		Monthly well supervision fees which are included in production expenses in the Partnership’s statements of operations are payable at $376 per well, per month in 2010 and 2009 for operating and maintaining the wells. Well supervision fees incurred for the years ended December 31, 2010 and 2009 were $829,900 and $855,500, respectively.

	•		Transportation fees which are included in production expenses in the Partnership’s statements of operations are generally payable at 13% of the natural gas sales price. Transportation fees incurred for the years ended December 31, 2010 and 2009 were $576,900 and $831,300, respectively.

	•		Direct costs which are included in production and general administrative expenses in the Partnership’s statements of operations are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf. Direct costs incurred for the years ended December 31, 2010 and 2009 were $444,300 and $535,100, respectively.

	•		Assets returned to the MGP, which are disclosed in the Partnership’s statements of cash flows as a non-cash activity for the year ended December 31, 2009, was $9,500.

The MGP and its affiliates perform all administrative and management functions for the Partnership including billing revenues and paying expenses. Accounts receivable—affiliate on the Partnership’s balance sheets represents the net production revenues due from the MGP.

ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2010 AND 2009

NOTE 8 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS (Continued)

Subordination by Managing General Partner

Under the terms of the partnership agreement, the MGP may be required to subordinate up to 50% of its share of net production revenues of the Partnership to the benefit of the limited partners for an amount equal to at least 10% of their net subscriptions, determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution to the investor partners (July 2007) and expiring 60 months from that date. For the year ended December 31, 2010, the MGP was required to subordinate $487,100. Therefore, MGP net production revenues were decreased and the limited partners were increased by $487,100 as shown on the statement of changes in partners’ capital for the year ended December 31, 2010. For the year ended December 31, 2009, the MGP was required to subordinate $888,100. Therefore, MGP net production revenues were decreased and the limited partners were increased by $888,100 as shown on the statement of changes in partners’ capital for the year ended December 31, 2009.

NOTE 9 — COMMITMENTS AND CONTINGENCIES

Subject to certain conditions, investor partners may present their interests beginning in 2010 for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the units in any calendar year. In the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation.

Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, may retain $200 per month; per well to cover estimated future plugging and abandonment costs. As of December 31, 2010, the MGP has not withheld any such funds.

Legal Proceedings

The Managing General Partner is not aware of any legal proceedings filed against the Partnership.

The Partnership’s MGP is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations.

NOTE 10 — NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)

(1) Capitalized Costs Related to Oil and Gas Producing Activities

The following table presents the capitalized costs related to natural gas and oil producing activities at the periods indicated:


	December 31,
	2010			2009
Leasehold interest:	$	1,687,400		$	1,716,900
Wells and related equipment		86,251,900			86,402,200
Accumulated depletion		(76,882,900	)		(70,413,300	)

Net capitalized cost	$	11,056,400		$	17,705,800

ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2010 AND 2009

NOTE 10 — NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) (Continued)

(2) Oil and Gas Reserve Information

The preparation of the Partnership’s natural gas and oil reserve estimates were completed in accordance with its prescribed internal control procedures, which include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. For the year ended December 31, 2010, the Partnership retained Wright & Company, independent, third-party reserves engineers, to prepare a report of proved reserves. The reserves report included a detailed review of our properties. Wright & Company’s evaluation was based on more than 35 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations applicable as of December 31, 2010. The Wright & Company report was prepared in accordance with generally accepted petroleum engineering and evaluation principles.

The reserve disclosures that follow reflect estimates of proved reserves consisting of proved developed, net to the Partnership’s interests, of natural gas, crude oil, condensate and NGLs owned at year end and changes in proved reserves during the previous two years. Proved developed reserves are those proved reserves, which can be expected to be recovered from existing wells with existing equipment and operating methods.

There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of the Partnership’s oil and gas reserves or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas prices and in production and development costs and other factors for effects have not been proved.


	Natural Gas			Oil
	(Mcf)			(Bbls)
Balance at December 31, 2008		6,919,500			12,800
Production		(869,800	)		(2,200	)
Revisions to previous estimates		(154,800	)		3,000


Balance at December 31, 2009		5,894,900			13,600
Production		(696,900	)		(1,600	)
Revisions to previous estimates		(812,300	)		(2,100	)


Balance at December 31, 2010		4,385,700			9,900

ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2010 AND 2009

NOTE 11 — SUBSEQUENT EVENTS

Atlas Energy, Inc. Asset Acquisition

On February 17, 2011, Atlas Pipeline Holdings, L.P. (“AHD”) (NYSE: AHD), a then-majority owned subsidiary of Atlas Energy and parent of the general partner to Atlas Pipeline Partners, L.P. (“APL”) (NYSE: APL), completed an acquisition of assets from Atlas Energy, which included its investment management business, proved reserves located in the Appalachian Basin, New Albany Shale, Antrim Shale, Chattanooga Shale and Niobrara formation, and other assets (“Asset Acquisition”). As part of the transaction, Atlas Resources, LLC became an indirect subsidiary of AHD. Concurrent with the Asset Acquisition, Atlas Energy and its subsidiaries completed a merger transaction with Chevron Corporation (“Chevron”), whereby each share of Atlas Energy was converted into the right to receive $38.25 in cash as well as a pro rata distribution of all AHD common units owned by Atlas Energy, and Atlas Energy became a wholly-owned subsidiary of Chevron (“Merger”). Subsequent to the Merger, AHD changed its name to Atlas Energy, L.P.

Laurel Mountain Sale

Concurrently with the completion of the Asset Acquisition, APL, an affiliate of the MGP, completed its sale to Atlas Energy Resources, LLC of its 49% non-controlling interest in the Laurel Mountain joint venture.

Hedge Monetization

In conjunction with the “Asset Acquisition,” Atlas Energy monetized all derivative contracts related to natural gas and oil production. The Partnership will share in the total available hedge gains with all other Partnerships sponsored by the MGP. Each Partnership will participate in the monetized funds based on its production volumes during the period of the original derivative contracts.


ITEM 9.		CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE:

None.


ITEM 9A.		CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, concluded that, as of December 31, 2010, our disclosure controls and procedures were effective at the reasonable assurance level.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of management, including our Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, we conducted an evaluation of the effectiveness of internal control over financial reporting based upon criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission inInternal Control — Integrated Framework(COSO framework).

An effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, effectiveness of an internal control system in future periods cannot be guaranteed because the design of any system of internal controls is based in part upon assumptions about the likelihood of future events. There can be no assurance that any control design will succeed in achieving its stated goals under all potential future conditions. Over time certain controls may become inadequate because of changes in business conditions, or the degree of compliance with policies and procedures may deteriorate. As such, misstatements due to error or fraud may occur and not be detected.

Based on our evaluation under the COSO framework, management concluded that our internal control over financial reporting as of December 31, 2010 was effective.

This annual report does not include an attestation report by the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to the rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.


ITEM 9B.		OTHER INFORMATION

None.

PART III


ITEM 10.		DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Atlas Energy is headquartered at Westpointe Corporate Center One, 1550 Coraopolis Heights Road, 2^nd Floor, Moon Township, Pennsylvania 15108, which is also our MGP’s primary office.

Executive Officers and Directors.The executive officers and directors of our MGP will serve until their successors are elected. The executive officers and directors of our MGP are as follows:


NAME	AGE		POSITION OR OFFICE

Freddie M. Kotek		55	Chairman of the Board of Directors, Chief Executive Officer and President
Jeffrey C. Simmons		52	Executive Vice President — Operations and a Director
Jack L. Hollander		54	Senior Vice President — Direct Participation Programs
Sean P. McGrath		39	Chief Financial Officer

With respect to the biographical information set forth below:

•

the approximate amount of an individual’s professional time devoted to the business and affairs of our MGP and Atlas Energy have been aggregated because there is no reasonable method for them to distinguish their activities between the two companies; and

•

for those individuals who also hold senior positions with other affiliates of our MGP, if it is stated that they devote approximately 100% of their professional time to our MGP and Atlas Energy, it is because either the other affiliates are not currently active in drilling new wells, such as Viking Resources or Resource Energy, and the individuals are not required to devote a material amount of their professional time to the affiliates, or there is no reasonable method to distinguish their activities between our MGP and Atlas Energy as compared with the other affiliates of our MGP, such as Viking Resources or Resource Energy.

Freddie M. Kotekhas been an Executive Vice President since February 2004 and served as a director from September 2001 until February 2004. Mr. Kotek has been Chairman of Atlas Resources, LLC since September 2001 and has served as an Executive Vice President since October 2009. He has also served as Chief Executive Officer and President of Atlas Resources since January 2002. Mr. Kotek was our Chief Financial Officer from February 2004 until March 2005. Mr. Kotek was a Senior Vice President of Resource America from 1995 until May 2004 and President of Resource Leasing, Inc. (a wholly-owned subsidiary of Resource America) from 1995 until May 2004. Kotek will devote approximately 95% of his professional time to the business and affairs of the MGP and Atlas Energy, Atlas Energy Resources, LLC and Atlas Energy Management, Inc., and the remainder of his professional time to the business and affairs of the MGP’s other affiliates.

Jeffrey C. Simmons.Executive Vice President-Operations and a Director since January 2001. Mr. Simmons has been an Executive Vice President of Atlas America since January 2001 and was a Director of Atlas America from January 2002 until February 2004. Mr. Simmons has been a Senior Vice President of Atlas Energy Management, Inc., since 2006. Mr. Simmons was a Vice President of Resource America from April 2001 until May 2004 when he resigned from Resource America. Mr. Simmons served as Vice President of Operations for the MGP from July 1999 until December 2000 and for Atlas America from 1998 until December 2000. Mr. Simmons joined Resource America in 1986 as a senior petroleum engineer and has served in various executive positions with its energy subsidiaries since then. Mr. Simmons received his Bachelor of Science degree with honors from Marietta College in 1981 and his Masters degree in Business Administration from Ashland University in 1992. Mr. Simmons devotes approximately 90% of his professional time to the business and affairs of the MGP, Atlas Energy, and the remainder of his professional time to the business and affairs of the MGP’s other affiliates, primarily Viking Resources and Resource Energy, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.

Jack L. Hollander.Senior Vice President — Direct Participation Programs since January 2002 and before that he served as Vice President — Direct Participation Programs from January 2001 until December 2001. Mr. Hollander also serves as Senior Vice President — Direct Participation Programs of Atlas America since January 2002. Mr. Hollander practiced law with Rattet, Hollander & Pasternak, concentrating in tax matters and real estate transactions, from 1990 to January 2001, and served as in-house counsel for Integrated Resources, Inc. (a diversified financial services company) from 1982 to 1990. Mr. Hollander earned a Bachelor of Science degree from the University of Rhode Island in 1978, his law degree from Brooklyn Law School in 1981, and a Master of Law degree in Taxation from New York University School of Law Graduate Division in 1982. Mr. Hollander is a member of the New York State bar, and the Chairman of the Investment Program Association which is an industry association, as of March 2005. Mr. Hollander devotes approximately 100% of his professional time to the business and affairs of the MGP, Atlas Energy, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.

Sean P. McGrathChief Financial Officer. Mr. McGrath was Chief Accounting Officer of Atlas Energy and Atlas Energy Resources, LLC from December 2008 until February 2011. Mr. McGrath served as Chief Accounting Officer of Atlas Pipeline Holdings GP, LLC from January 2006 until November 2009 and as Chief Accounting Officer of Atlas Pipeline Partners GP, LLC from May 2005 until November 2009. Mr. McGrath was the Controller of Sunoco Logistics Partners L.P., a publicly-traded partnership that transports, terminals and stores refined products and crude oil, from 2002 until 2005. Mr. McGrath is a Certified Public Accountant.

Audit Committee Financial Expert.The Board of Directors of our MGP acts as the audit committee. The Board of Directors has determined that Freddie M. Kotek, Chairman and President of the MGP, meets the requirement of an “audit committee financial expert.” He is not independent.

Remuneration of Officers and Directors.No officer or director of the MGP will receive any direct remuneration or other compensation from the Partnership. These persons will receive compensation solely from affiliated companies of the MGP.

Code of Business Conduct and Ethics.Because the Partnership does not directly employ any persons, the MGP has determined that the Partnership will rely on a Code of Business Conduct and Ethics adopted by Atlas Energy, Inc. and/or Atlas Energy Resources, LLC that applies to the principal executive officer, principal financial officer and principal accounting officer of the MGP, as well as to persons performing services for the MGP generally. You may obtain a copy of this Code of Business Conduct and Ethics by a request to the MGP at Atlas Resources, LLC, Westpointe Corporate Center One, 1550 Coraopolis Heights Road, 2^nd Floor, Moon Township, Pennsylvania 15108.


ITEM 11.		EXECUTIVE COMPENSATION

We have no employees and rely on the employees of our MGP and its affiliates for all services. No officer or director of our MGP will receive any direct remuneration or other compensation from us. Those persons will receive compensation solely from affiliated companies of our MGP. See Item 13Certain Relationships and Related Party Transactionsfor a discussion of compensation paid by us to our MGP.


ITEM 12.		SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

As of December 31, 2010, we had 2,840 units outstanding. No officer or director of our MGP owns any units. Although, subject to certain conditions, investor partners may present their units to us beginning in 2010 for purchase, the MGP is not obligated by the Partnership Agreement from purchasing more than 5% of our total outstanding units in any calendar year. The MGP is owned 100% by Atlas Energy Resources, LLC, whose ultimate parent is Atlas Energy.


ITEM 13.		CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Oil and Gas Revenues.Our MGP is allocated 32.54% of our oil and gas revenues in return for its payment and/or contribution of services towards our syndication and offering costs equal to 12% of our subscriptions, its payment of 60.07% of the tangible costs of drilling and completing our wells and its contribution to us of all of our oil and gas leases. These capital contributions from our MGP totaled $24,307,100. During the years ended December 31, 2010 and 2009, our MGP received $721,500 and $859,800, respectively, from our net production revenues.

Administrative Costs.Our MGP and its affiliates receive an unaccountable, fixed fee reimbursement for the administrative costs they incur on our behalf of $75 per well per month, which is proportionately reduced if we acquire less than 100% of the working interest in a well. During the years ended December 31, 2010 and 2009, our MGP received $165,600 and $170,700, respectively for its administrative costs.

Direct Costs.Our MGP and its affiliates are reimbursed by us all direct costs expended by them on our behalf. During the years ended December 31, 2010 and 2009, our MGP’s received $444,300 and $535,100, respectively as reimbursement for direct costs.

Well Charges.Our MGP, as operator of our wells, is reimbursed at actual cost for all direct expenses incurred on our behalf and receives well supervision fees for operating and maintaining the wells during producing operations in the amount of $376 per well per month in 2010 and 2009, subject to an annual adjustment for inflation. The well supervision fees are proportionately reduced to the extent we acquire less than 100% of the working interest in a well. For the years ended December 31, 2010 and 2009, our MGP received $829,900 and $855,500, respectively for well supervision fees.

Transportation Fees.We pay gathering fees to our MGP at a competitive rate for each mcf of our natural gas transported. The transportation rate is generally 13% of the natural gas sales price. For the years ended December 31, 2010 and 2009, $576,900 and $831,300 respectively was paid to our MGP for gathering fees. In turn, our MGP paid 100% of this amount to Atlas Energy, for the use of its gathering system in transporting a majority of our natural gas production.

Other Compensation.For the year ended December 31, 2010 our MGP did not advance any funds to us, or did they provide us with any equipment, supplies, or other services.


ITEM 14.		PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees.The aggregate fees billed by from our independent auditors, Grant Thornton LLP, for professional services rendered for the audit of our annual financial statements for the years ended December 31, 2010 and 2009, and for the reviews of the financial statements included in our quarterly reports on Form 10-Q during such years were $33,200 and $31,600, respectively.

Procedures for Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditor.Pursuant to its charter, the Audit Committee of Atlas Energy, Inc. is responsible for reviewing and approving, in advance, any audit and any permissible non-audit engagement or relationship between us and our independent auditors. We do not have a separate audit committee.

PART IV


ITEM 15.		EXHIBITS

EXHIBIT INDEX


		Description	Location

4	(a)	Certificate of Limited Partnership for Atlas America Series 27-2006 L.P.	Previously filed in our Form S-1 on August 9, 2005

4	(b)	Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Series 27-2006 L.P.⁽¹⁾	Previously filed in our Form S-1 on August 9, 2005

4	(c)	Drilling and Operating Agreement for Atlas America Series 27-2006 L.P.	Previously filed in our Form S-1 on August 9, 2005

23.1		Consent of Wright and Company, Inc.

31.1		Rule 13a-14(a)/15(d) — 14 (a) Certification

31.2		Rule 13a-14(a)/15(d) — 14 (a) Certification.

32.1		Section 1350 Certification.

32.2		Section 1350 Certification.

99.1		Summary Reserve Report


(1)		Filed on April 30, 2007 in the Form S-1 Registration Statement dated April 30, 2007, File No. 0-52615

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Atlas America Series 27-2006 L.P.


Date: March 30, 2011	Atlas Resources, LLC, Managing General Partner
	By:	/s/ Freddie M. Kotek
		Freddie M. Kotek, Chairman of the Board of Directors, Chief Executive Officer and President

In accordance with the Exchange Act, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Date: March 30, 2011	By:	/s/ Freddie M. Kotek
		Freddie M. Kotek, Chairman of the Board of Directors, Chief Executive Officer and President

Date: March 30, 2011	By:	/s/ Jeffrey C. Simmons
		Jeffrey C. Simmons, Executive Vice President — Operations

Date: March 30, 2011	By:	/s/ Sean P. McGrath
		Sean P. McGrath, Chief Financial Officer

Supplemental information to be furnished with reports filed pursuant to Section 15(d) of the
Exchange Act by Non-reporting Issuers

An annual report will be furnished to security holders subsequent to the filing of this report.

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Atlas America Series 27-2006 Inactive 10-K2010 FY Annual report

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